Natural gas contains varying percentages of the following components: carbon dioxide, hydrogen sulfide, lower aliphatic hydrocarbons such as methane, ethane, propane, butanes, pentanes, hexanes and small amounts of aliphatic hydrocarbons having more than six carbon atoms, water, nitrogen, and trace amounts of gases such as mercaptans, carbonyl sulfide, helium and argon.
To be commercially acceptable, natural gas must meet stringent specifications with respect to heating value and the content of certain components. For example, a sufficient amount of hydrogen sulfide must be removed from the natural gas so that the gas product has an H.sub.2 S concentration of no more than about 1/4 to about 1/2 grains per 100 standard cubic feet. Desirably, the carbon dioxide content of the gas product should be less than about two mole percent since higher concentrations can be corrosive. Also, carbon dioxide should be removed because its presence in a gas reduces that gas's heating value.
Acid gases such as H.sub.2 S and CO.sub.2 may be removed from hydrocarbon gas streams such as natural gas by many methods. These methods may be broadly classified as chemical reaction absorption, physical absorption and adsorption. The chemical reaction processes rely on a reversible chemical reaction and, in particular, use an absorbent which reacts with CO.sub.2 and/or H.sub.2 S in a contactor. The absorbent can be regenerated by use of a high temperature stripper. Chemical reaction processes include the amine processes such as the monoethanolamine (MEA) process, the diethanolamine (DEA) process and the sulfinol process which used a sulfolane (tetrahydrothiophene dioxide)-di-isopropanolamine (DIPA)-water mixture; the diglycolamine processes; the hot carbonate processes such as the Benfield, Girdler, Catacarb and Giammarco-Vetrocoke processes; and the iron-sponge processes which use a solution of quinone to convert H.sub.2 S to sulfur.
The physical absorption processes rely on the affinity of certain chemicals for CO.sub.2 and H.sub.2 S and, basically, employ a contactor to remove the acid gases from the feed stream. Also, a stripper is used to separate the acid gases from the absorbent. These absorption processes include the patented Fluor solvent process which uses a refrigerated solvent consisting of anhydrous propylene carbonate; the Selexol process which may use the dimethylether of polyethylene glycol as a solvent alone or in combination with DIPA if low partial pressures of H.sub.2 S in the product are required; the Sulfinol process which employs both a physical and a chemical solvent; and the Rectisol process which uses methanol as a solvent.
The adsorption processes are based on the unique adsorbent characteristics of certain minerals such as zeolitis. Generally, these adsorption processes are batch-type processes employing a molecular sieve. In operation the acid gas components of the feed gas stream are adsorbed on the surface of the mineral used and are subsequently removed from the mineral surface during a high temperature regeneration cycle. Molecular sieve processes can be designed to simultaneously dehydrate and sweeten natural gas streams.
All of the above-mentioned processes are not particularly attractive processes when the parameters often employed to evaluate various processes are reviewed. These parameters include: Capital cost, energy consumption, plant area requirements, manpower for operation and maintenance costs. The processes become more uneconomical for treating sour natural gas as the cost of the processes, evaluated with the above parameters, continue to increase. For example, on the North Slope of Alaska and on offshore platforms, the area available for process systems is extremely expensive and, hence, it follows that systems used at those locations should have small area requirements.
With regard to the high energy requirements of the above-mentioned systems, it is well known by those in the art that those systems are highly energy intensive. Molecular sieves, for example, must be heated to and held at approximately 600.degree. F. during regeneration in order to remove all of the adsorbed material from the mineral surfaces. High energy input is required to achieve such temperatures. Further, it may be estimated that in the absorption processes three to seven standard cubic feet of acid gas can be removed in the absorber per each gallon of absorbent and from 1000 to about 1200 BTUs of heat per gallon of absorbent are required to remove the acid gas from the absorbent.
High capital investment and high operating costs of the above-described processes can be attributed, in part, to the wall thickness of the vessels required and the large number of pieces of equipment normally required. Normally, natural gas is sweetened at high pressures in order to minimize or avoid compression of the ultimate product.
Other processes have been used to separate one or more gaseous components from a gaseous mixture. In particular, membranes have been used for many years in gas separation. An excellent source of information concerning membrane technology is Hwang and Kammermeyer's MEMBRANES IN SEPARATION, which is Volume VII of a series entitled Techniques of Chemistry (Weissberger, ed. 1975).
Gas permeation may be defined as a physical phenomenon in which certain components selectively pass through a substance such as a membrane. Basically, a gas permeation process involves introducing a gas into one side of a module which is separated into two compartments by a permeable membrane. The gas stream flows along the surface of the membrane and the more permeable components of the gas pass through the membrane barrier at a higher rate than those components of lower permeability. After contacting the membrane, the depleted feed gas residue stream is removed from contact with the membrane via a suitable outlet on the feed compartment side of the vessel. The other side of the membrane, the permeate side, is provided with a suitable outlet through which the permeated gaseous components can be removed from contact with the membrane.
The purpose of a membrane in a gas permeation process is to act as a selective barrier, that is, to permit passage of some but not all components of a gaseous feed stream. Generally, in gaseous membrane separation processes, the separation is due to molecular interaction between gaseous components of the feed stream and the membrane. Because different components react differently with the membrane, the transmission rates (permeation fluxes) are different for each component. Hence, separation of different components can be effected.
Usually, permeation through a membrane involves both the diffusivity and solubility of the permeated component in and through the membrane. An exception to this occurs in microporous membranes wherein permeation proceeds purely on the basis of Knudsen (free molecular) diffusion, assuming the pores are sufficiently small. In actuality, the absorptive characteristics of gases may not be negligible and are usually temperature, pressure and surface flow dependent.
The membrane separation process involves several phenomena which occur as the more permeable components of the gaseous feed mixture pass over, through and out the other side of the membrane. Basically, mass transfer through a membrane proceeds by the sorption of a gaseous component on the feed side of the membrane, diffusion of that component through the membrane, and desorption of the component from the permeate side of the membrane. Each of these steps causes some resistance to the free flow of gaseous components through the membrane. Generally the diffusion step provides the most resistance to gas component transfer through the membrane barrier.
A gas permeation process may be comprised of one permeation module or a series of modules depending on the degree of separation desired. Many types of membranes, including cellulose esters and polymeric membranes such as silicone rubber, polyethylene, and polycarbonate, may be employed; however, the particular membrane used depends upon the type of separation sought to be effected. For example, if it is desired to separate helium from natural gas, a dried cellulose acetate membrane may be used since that membrane has a higher permeability for helium than for the hydrocarbons contained in natural gas.
For many years, cellulose ester membranes have been used for the desalination of salt water by reverse osmosis. A method of preparing cellulose acetate membranes is disclosed in U.S. Pat. No. 3,884,801. Typically, these membranes are water wet and do not exhibit good gas permeable properties in such condition. Years ago, it was discovered that if properly dried, these membranes could be used for gas separation. For example, U.S. Pat. No. 3,415,038 discloses several methods of drying cellulose acetate membranes. That patent also discloses that the dried cellulose acetate membranes can be used to separate helium from natural gas and to separate hydrogen from a mixture of hydrogen and carbon monoxide.
Other patents disclose the use of membranes in gas separation processes. For example, U.S. Pat. No. 3,842,515 discloses a method for drying cellulose acetate membranes and also discloses that these dried membranes may be used to separate helium from natural gas.
U.S. Pat. No. 2,947,687 disclosed that hydrocarbons may be separated according to type, molecular configuration, boiling point or molecular weight by using a non-porous membrane. It was further disclosed that the preferred membrane was an ethyl cellulose membrane having an ethoxyl content between 40 to 47 percent by weight.
In U.S. Pat. No. 3,335,545, it was disclosed that liquid or quasi-liquid barriers could be used for the separation of gaseous components from a mixture. In particular, it was disclosed that with a composite film of water and silicone the separation factor for CO.sub.2 /O.sub.2 was 22-30 and about 20 for CO.sub.2 /H.sub.2 S. Further, it was disclosed that a composite film comprised of a 70 mil agar-agar-water gel film supported on a 3 mil silicone rubber film had the permeation constants of 10.times.10.sup.-10 and 244.times.10.sup.-9 cc. of gas, cm./sec., cm.sup.2, cm.Hg. for oxygen and carbon dioxide respectively.
Another area of technology to which this invention has application is in enhanced oil recovery processes. After primary oil recovery from reservoirs, enhanced oil recovery has to be obtained by reservoir pressure maintenance and by waterflooding. Ultimate oil recovery, however, it quite limited by the application of these conventional methods. Today, other types of recovery processes are being utilized. These processes include steam flooding, chemical treatment (polymer flooding) and carbon dioxide flooding. Of these, carbon dioxide appears to have the best potential for obtaining the maximum oil recovery at a reasonable cost. The carbon dioxide flooding may be used alone or in conjunction with waterflooding.
Carbon dioxide flooding (CF) is known in the art to be quite useful in enhanced oil recovery processes. CF performs this task by many mechanisms including: (1) immiscible CO.sub.2 drive; (2) miscible CO.sub.2 drive; (3) hydrocarbon-CO.sub.2 miscible drive; (4) solution gas drive; (5) hydrocarbon vaporization; and (6) multiple-contact dynamic miscible drive. In the L. W. Holm and V. A. Josendal, December 1974 paper published in the Journal of Petroleum Technology, the CO.sub.2 properties which are important in effecting oil displacement are listed as follows: (1) CO.sub.2 reduces oil viscosity; (2) CO.sub.2 increases oil density; (3) CO.sub.2 promotes swelling of oil; (4) CO.sub.2 is highly soluble in water; (5) CO.sub.2 in water has an acidic affect on limestone or carbonate rock by dissolving the rock and shrinking clays; (6) CO.sub.2 vaporizes and extracts portions of crude oil; and (7) CO.sub.2 is transported chromatographically through porous rock.
Although miscible flooding with CO.sub.2 is becoming more popular, there are definite disadvantages. For example, the effectiveness of CO.sub.2 is reduced in the presence of impurities such as methane and nitrogen. Apparently, the above mentioned impurities interfere with the dissolution of CO.sub.2 in the crude oil. If the combined concentrations of methane and nitrogen in the CO.sub.2 rich stream exceeds more than about 5 mole percent, the effectiveness of CO.sub.2 appears to be severely reduced. Accordingly, an economical method for producing a rich CO.sub.2 stream substantially free of impuritites such as methane and nitrogen is required.